The present invention relates to a device for locking a tubing hanger to a tubing spool or the like in a subsea completion system. More particularly, the invention relates to such a device which is operable independently of both the tubing hanger and the tubing hanger running tool.
A typical prior art completion system for subsea oil and gas wells comprises a subsea wellhead which is installed at the upper end of a well bore, a production member which is connected to the top of the wellhead, and a tubing hanger which is landed in the production member and which supports a production tubing string that extends through the well bore and into the well. During installation and workover operations, the subsea completion system is often connected to a surface vessel through a low pressure riser which in turn is connected to a subsea blowout preventor (“BOP”) that is secured to the top of the production member.
The tubing hanger is normally installed in the production member using a tubing hanger running tool (“THRT”). In addition, once the tubing hanger is landed in the production member, a lockdown mechanism is usually actuated to secure the tubing hanger to the production member. A typical lockdown mechanism includes a lock ring which is supported on the tubing hanger and is expandable into locking engagement with a corresponding groove that is formed in the production member. Furthermore, once the tubing hanger is secured to the production member, a release mechanism on the THRT is actuated to release the tubing hanger from the THRT.
Thus, prior art THRT's must usually include a lockdown tool for actuating the lockdown mechanism on the tubing hanger and a release tool for actuating the release mechanism on the THRT. Moreover, these tools are often operated by hydraulic pressure which is supplied to the THRT through a hydraulic umbilical that is connected to the surface vessel.
When employing such a hydraulically operated THRT, however, safety and contingency concerns often require that a subsea test tree (“SSTT”) and a shear joint also be used. In this arrangement, the SSTT is connected to the top of the THRT, the shear joint is connected to the top of the SSTT, and the entire assembly is lowered on a running string through the low pressure riser and the BOP. In addition, the hydraulic umbilical for the THRT is run along side the running string and then routed to the THRT through the shear joint and the SSTT.
The SSTT and the shear joint allow for a controlled shut-in of the well in the event of a blowout or other emergency. When such an event occurs, the valves in the SSTT are closed, the lower BOP pipe rams are sealed around the SSTT and, if necessary, the upper BOP shear rams are actuated to sever the shear joint and thereby separate the running string from the SSTT. After the well has been brought back under control, the lower portion of the severed shear joint can be retrieved and a replacement shear joint then re-connected to the SSTT.
Thus, the SSTT and the shear joint allow for hydraulic control of the THRT to be easily re-established. Once the replacement shear joint is connected to the SSTT, the hydraulic umbilical is again connected with the THRT. Without the SSTT and the shear joint, the BOP shear rams would sever the hydraulic umbilical and control of the THRT would be lost. Depending on the status of the tubing hanger lockdown and release mechanisms when control is lost, this can be a very costly and time consuming problem to fix.
Wile adequate for many applications, prior art hydraulically operated THRT's have several disadvantages which have become more problematic as subsea wells are drilled in deeper and deeper waters. First, hydraulic umbilicals are subject to collapse due the extreme hydrostatic pressures experienced at great depths. This can result in a temporary or permanent loss of control of the THRT or, in the worst case, a premature release and consequent dropping of the tubing hanger and the production tubing into the well.
Second, some operators prefer to use a surface BOP and a smaller diameter high pressure riser to connect the surface vessel to the production member in deep water. In this arrangement, the hydraulic umbilical for the THRT is routed through a “slick joint” in the running string which is positioned in the surface BOP. However, this requires that the umbilical be cut to a precise length in order to properly “space out” the slick joint, and this can be a difficult and expensive undertaking.
Third, as wells are drilled in progressively deeper waters, the use of “slimbore” completion systems is becoming increasingly popular. These systems comprise production members which have relatively small drift diameters. Consequently, the tubing hangers and THRT's for such systems must have correspondingly small diameters. However, when the tubing hanger lockdown mechanism is supported on the tubing hanger and the lockdown tool is incorporated in the THRT, minimizing the diameter of these components can be a challenge.